Resuming interrupted communication through a wellbore

ABSTRACT

Resuming communication along a wellbore after a drilling stand or other occurrence that reduces the flow rate of the drilling fluid into a borehole being drilled in a drilling procedure or causes perturbations in the pressure of the drilling fluid in the borehole by measuring a first flow rate of drilling fluid being pumped into the drillstring during the drilling procedure before adding a section of drill pipe to the drillstring or before the pressure perturbation and increasing the flow rate of the drilling fluid being pumped into the drillstring above the first flow rate after the section of drill pipe has been added to the drillstring or the pressure perturbation has occurred.

BACKGROUND

Wells/boreholes are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. A well/borehole is typically drilled using a drill bit attached to the lower end of a drillstring. The well is drilled so that it penetrates the subsurface formations containing the trapped materials and the materials can be recovered.

At the bottom end of the drillstring is a “bottom hole assembly” (“BHA”). The BHA includes the drill bit along with sensors, control mechanisms, and the required circuitry. A typical BHA includes sensors that measure various properties of the formation and of the fluid that is contained in the formation. A BHA may also include sensors that measure the BHA's orientation and position.

The drilling operations may be controlled by an operator at the surface or operators at a remote operations support center. The drill string is rotated at a desired rate by a rotary table, or top drive, at the surface, and the operator controls the weight-on-bit and other operating parameters of the drilling process.

Another aspect of drilling and well control relates to the drilling fluid, called “mud.” The mud is a fluid that is pumped from the surface to the drill bit by way of the drill string. The mud serves to cool and lubricate the drill bit, and it carries the drill cuttings back to the surface. The density of the mud is carefully controlled to maintain the hydrostatic pressure in the borehole at desired levels.

In order for the operator to be aware of the measurements made by the sensors in the BHA/along the drillstring etc. and/or for the operator to be able to control the direction of the drill bit, communication between the operator at the surface and the BHA are necessary. A “downlink” is a communication from the surface to the BHA. Based on the data collected by the sensors in the BHA, an operator may desire to send a command to the BHA. A common command is an instruction for the BHA to change the direction of drilling.

Likewise, an “uplink” is a communication from the BHA/downhole sensors/processor to the surface. An uplink is typically a transmission of the data collected by the downhole sensors. For example, it is often important for an operator to know the BHA orientation. Thus, the orientation data collected by sensors in the BHA is often transmitted to the surface. Uplink communications are also used to confirm that a downlink command was correctly understood.

One common method of communication is called “mud pulse telemetry.” Mud pulse telemetry is a method of sending signals, either downlinks or uplinks, by creating pressure and/or flow rate pulses in the mud. These pulses may be detected by sensors at the receiving location. For example, in a downlink operation, a change in the pressure or the flow rate of the mud being pumped down the drill string may be detected by a sensor in the BHA. The pattern of the pulses, such as the frequency, the phase, and the amplitude, may be detected by the sensors and interpreted so that the command may be understood by the BHA.

One method of mud pulse telemetry is disclosed in U.S. Pat. No. 3,309,656, comprises a rotary valve or “mud siren” pressure pulse generator which repeatedly interrupts the flow of the drilling fluid, and thus causes varying pressure waves to be generated in the drilling fluid at a carrier frequency that is proportional to the rate of interruption. Downhole sensor response data is transmitted to the surface of the earth by modulating the acoustic carrier frequency. A related design is that of the oscillating valve, as disclosed in U.S. Pat. No. 6,626,253, wherein the rotor oscillates relative to the stator, changing directions every 180 degrees, repeatedly interrupting the flow of the drilling fluid and causing varying pressure waves to be generated.

Referring now to FIG. 1A, a wellbore telemetry system 100 is depicted including a downhole measurement while drilling (MWD) tool 34 is incorporated in the drill string 14 near the drill bit 16 for the acquisition and transmission of downhole data or information. The MWD tool 34 includes an electronic sensor package 36 and a mudflow wellbore telemetry device 38. The mudflow telemetry device 38 can selectively block the passage of the mud 20 through the drill string 14 to cause pressure changes in the mud line 26. In other words, the wellbore telemetry device 38 can be used to modulate the pressure in the mud 20 to transmit data from the sensor package 36 to the surface 29. Modulated changes in pressure are detected by a pressure transducer 40 and a pump piston sensor 42, both of which are coupled to a surface system processor (not shown). The surface system processor interprets the modulated changes in pressure to reconstruct the data collected and sent by the sensor package 36. The modulation and demodulation of a pressure wave are described in detail in commonly assigned U.S. Pat. No. 5,375,098, which is incorporated by reference herein in its entirety.

The surface system processor may be implemented using any desired combination of hardware and/or software. For example, a personal computer platform, workstation platform, etc. may store on a computer readable medium (e.g., a magnetic or optical hard disk, random access memory, etc.) and execute one or more software routines, programs, machine readable code or instructions, etc. to perform the operations described herein. Additionally or alternatively, the surface system processor may use dedicated hardware or logic such as, for example, application specific integrated circuits, configured programmable logic controllers, discrete logic, analog circuitry, passive electrical components, etc. to perform the functions or operations described herein.

Still further, while the surface system processor can be positioned relatively proximate to the drilling rig (i.e., substantially co-located with the drilling rig), some part of or the entire surface system processor may alternatively be located relatively remotely from the rig. For example, the surface system processor may be operationally and/or communicatively coupled to the wellbore telemetry component 18 via any combination of one or more wireless or hardwired communication links (not shown). Such communication links may include communications via a packet switched network (e.g., the Internet), hardwired telephone lines, cellular communication links and/or other radio frequency based communication links, etc. using any desired communication protocol.

Additionally one or more of the components of the BHA may include one or more processors or processing units (e.g., a microprocessor, an application specific integrated circuit, etc.) to manipulate and/or analyze data collected by the components at a downhole location rather than at the surface.

Mud pulse systems may use a single modulator, typically consisting of a stator and a rotor. The relative position between the stator and rotor, together with the drilling mud/fluid conditions, determine the amplitude of the telemetry signal generated. In addition, for a single modulator, the amplitude of the differential pressure signal generated is proportional to the square of the inverse of the flow area. The speed at which the rotor can be moved relative to the stator limits the bandwidth of the signal generated.

SUMMARY

A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth.

In one embodiment of the present invention, a method is provided for resuming communication through a drilling fluid being used in a borehole for a drilling procedure after an interruption. Merely by way of example, an interruption may comprise adding a section of pipe to a drillstring that is being used in the drilling procedure, where the flow rate of drilling fluid being pumped into the borehole is reduced when the drill pipe section is added to the drillstring causing perturbations in the drilling fluid in the borehole. The method to restore communication after an interruption may according to one embodiment comprise measuring a first flow rate of the drilling fluid being pumped into a drillstring during the drilling procedure before adding a section of drill pipe to the drillstring and increasing the flow rate of the drilling fluid pumped into the drillstring above the first flow rate immediately after the section of drill pipe has been added to the drillstring.

In another embodiment, a system for resuming communication through a drilling fluid being used in a borehole for a drilling procedure after an interruption. Merely by way of example, an interruption may comprise adding a section of pipe to a drillstring that is being used in the drilling procedure, where the flow rate of drilling fluid is reduced when the drill pipe section is added to the drillstring causing perturbations in the drilling fluid in the borehole. The system for resuming communication after an interruption in accordance with an embodiment of the present invention comprising a sensor configured to measuring a flow rate of drilling fluid being pumped into a drillstring during the drilling procedure, and a processor in communication with the sensor and configured to control the pump to increase a flow rate of the drilling fluid pumped into the drillstring above a first flow rate immediately after a section of drill pipe has been added to the drillstring, wherein the first flow rate is a flow rate of the drilling fluid pumped into the drillstring before the section of drill pipe has been added to the drillstring.

In one embodiment of the present disclosure, a method is provided for controlling flow rates of drilling mud being pumped into a drillstring during a drilling procedure to drill a borehole from a surface location through an earth formation in order to resume communication through the drilling fluid after an interruption, the method comprising:

establishing a range of desired optimal flow rates for pumping the drilling mud into the drillstring, wherein the optimal flow rates are determined so as to keep a bottomhole pressure in the borehole within an optimal operating pressure window having upper and lower pressure bounds;

drilling for a first period of time at a first optimal flow rate;

reducing the flow rate, wherein the reduced flow rate causes the interruption;

increasing the flow rate to a value above said first optimal flow rate;

reducing the flow rate to a second optimal flow rate, which may be the same or different to the first optimal flow rate, and wherein the second optimal flow rate, wherein the second optimal flow rate is configured to keep the bottomhole pressure in the borehole within the optimal operating pressure window.

In one embodiment of the present disclosure, a system is provided for controlling flow rates of drilling fluids being pumped into a drillstring during a drilling procedure to drill a borehole from a surface location through an earth formation, the system comprising:

a stored range of desired optimal flow rates for pumping the drilling fluids into the drillstring, wherein the optimal flow rates are determined so as to keep a bottomhole pressure in the borehole within an optimal operating pressure window having upper and lower pressure levels, wherein the upper pressure level comprises a pressure below a fracture pressure of the formation being drilled and the lower pressure level comprises a pressure above a pore pressure of the formation

one or more pumps configured to pump drilling fluid into the drillstring; and

a processor configured to control the one or more pumps, wherein the processor controls the pumps

-   -   to pump the drilling fluid at a first optimum flow rate, wherein         the optimum flow rate is within the range of desired optimal         flow rates;     -   after a reduction in the rate at which the drilling fluid is         pumped below the optimum flow rate, to pump the drilling fluid         into the drillstring at an increased flow rate that is greater         than the optimal flow rate; and     -   to reduce the flow rate to a second optimal flow rate, wherein         the second optimal flow rate is within the range of desired         optimal flow rates and may be the same or different to the first         optimal flow rate.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is described in conjunction with the appended figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1A illustrates a wellbore telemetry system that may be used with some embodiments of the present invention;

FIG. 1B illustrates an apparatus for resuming interrupted communication down a wellbore, according to one embodiment of the present invention;

FIG. 2 illustrates a flow rate transition according to current practice (solid line), and according to a method in accordance of the present invention;

FIG. 3 shows flow rates through a drill bit versus time for a conventional wellbore procedure and a according to one embodiment of the present invention; and

FIG. 4 shows stand-pipe pressures for a conventional wellbore procedure and a according to one embodiment of the present invention.

In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.

DESCRIPTION

Reference will now be made in detail to embodiments, examples of which are illustrated in the accompanying drawings and figures. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the subject matter herein. However, it will be apparent to one of ordinary skill in the art that the subject matter may be practiced without these specific details. In other instances, well-known methods, procedures, components, and systems have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.

It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step. The first object or step, and the second object or step, are both objects or steps, respectively, but they are not to be considered the same object or step.

The terminology used in the description of the disclosure herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the subject matter. As used in this description and the appended claims, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises,” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

As used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context. Similarly, the phrase “if it is determined” or “if [a stated condition or event] is detected” may be construed to mean “upon determining” or “in response to determining” or “upon detecting [the stated condition or event]” or “in response to detecting [the stated condition or event],” depending on the context.

Hydrocarbon drilling operations require a large quantity of downhole data to be collected and transmitted to the surface. Such data may include characteristics of the earth formations surrounding the borehole being drilled, drilling parameters, data relating to the size and configuration of the borehole and/or the like. The collection of information relating to conditions downhole is commonly referred to as “logging,” can be performed by several methods. One of these methods requires sensing devices to be lowered into the borehole on a wireline cable. However, collecting data using sensors suspended on a wireline requires cessation of the drilling process and/or removal of the drilling apparatus from the borehole. This is extremely costly and slows down the drilling process. Moreover, conditions may be changed by the cessation of the drilling procedure and/or removal of the drilling apparatus.

As a result, it is often desirable to collect data during the drilling process. By collecting and processing data during the drilling process, without the necessity of ceasing the drilling procedure or tripping the drilling assembly out of the borehole to insert a wireline logging tool, the driller can make accurate modifications or corrections, as necessary, to optimize performance while minimizing down time. Measuring conditions in the borehole and/or downhole operating parameters of the drilling system downhole during the drilling process is often referred to as “measurement-while-drilling” or “MWD.” Measuring properties of the formation being drilled and/or surrounding the borehole being drilled is often referred to as “logging while drilling” or “LWD.” While distinctions between MWD and LWD may exist, the terms MWD and LWD are often used interchangeably.

Drilling oil and gas wells may be carried out using a string of drill pipes connected together so as to form a drillstring. The drillstring extends from a drive mechanism at the surface, such as a top drive, down to the face of the formation being drilled. Connected to the lower end of the drillstring is a drill bit that is used to drill through the formation. In the drilling process, the drill bit is rotated in the borehole against the formation. Power is provided to the drill bit either from the top drive via the drillstring or from a downhole motor.

Drilling fluid, often referred to as drilling mud/mud, is pumped down through the drillstring during the drilling process at high pressures and volumes (for example, such pressures may be around 3000 p.s.i. at flow rates of up to 1400 gallons per minute) to emerge through nozzles and/or jets in the drill bit. The mud is used, among other things, to remove cuttings produced by the drilling of the formation from the bottom of the borehole. The mud pumped into the borehole travels down the drillstring, through the drill bit then back up to the surface via an annulus formed between the exterior of the drillstring and the wall of the borehole being drilled. On the surface, the drilling mud may be cleaned and then recirculated. The drilling mud not only carries the cuttings from the base of the borehole to the surface, it may also be used to cool the drill bit and, importantly, to balance the hydrostatic pressure in the rock formations.

If the pressure in the borehole produced by the drilling mud is less than the surrounding formation, fluids from the rock formations may enter the borehole during the drilling process and produce a kick, which is an undesirable drilling event. However, if the pressure in the borehole produced by the drilling mud exceeds the fracture pressure of the formation a fracture will be created in the wall of the borehole, which may result in loss of fluids from the borehole into the formation, this is also an undesirable drilling event. As such, it is very important that the pressure in the borehole is tightly controlled to avoid kicks and fluid loss. Considering that boreholes may be of the order of kilometers in length, management of the pressure in the borehole as it is being drilled is an extremely complicated task.

This optimal pressure which avoids kicks and fluid loss is termed herein the “optimal operating pressure window”. Because the pressure in the borehole is strongly influenced by the flow rate of drilling mud, the flow rate that provides this optimal pressure at steady state is termed herein as the “optimal operating flow rate window”. In general, a bottomhole pressure, the pressure at the bottom of the borehole is the pressure that is used to determine an optimal pressure in the borehole since the bottomhole pressure is in general the most extreme of the pressures in the borehole. As such, the optimal operating flow rate window may in general be calculated using the bottomhole pressure. Often there are no sensors to measure the bottomhole pressure and the pressure must be interpolated for other parameters, such as drilling mud properties, choke pressure, stand pipe pressure and/or the like.

In LWD and MWD sensors or transducers are often located at the lower end of the drillstring, which sensors/transducers, while drilling is in progress, continuously or intermittently sense downhole parameters. Telemetry systems are used to communicate the data acquired by the sensors to the surface. There are a number of telemetry systems, but mud pulse telemetry is one of the most widely used telemetry systems.

In mud pulse telemetry, acoustic signals are transmitted through the drilling mud in the borehole, where the drilling mud is circulated under pressure through the drill string during drilling operations. Information contained in the acoustic signals may be transmitted from the surface to the bottom of the borehole or from the bottom of the borehole to the surface. Data acquired by the downhole sensors is transmitted by suitably timing the generation of pressure pulses in the flowing drilling mud. The acoustic signals are received and decoded by a pressure transducer and computer.

In a mud pulse telemetry system, the drilling mud pressure in the drillstring may be modulated by means of a valve and control mechanism, generally termed a pulser or mud pulser. The pulser is usually mounted in a specially adapted drill collar positioned above the drill bit. The generated pressure pulse travels up the mud column inside the drillstring at the velocity of sound in the mud. Depending on the type of drilling fluid used, the velocity may vary between approximately 3000 and 5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string.

By way of example, a typical pulse rate is on the order of a pulse per second (1 Hz). The mud pulse signal is comprised of a pressure pulse at one of two amplitudes, indicating whether the mud pulser is open or closed. If the pulser is closed, a high pressure pulse is generated, to indicate, for example, a digital “1.” If the pulser is opened, a digital “0” is indicated. The primary method of increasing the data rate of the transmitted signal is to increase the frequency (f) of the pulses. As the frequency f of the pulses increases, however, it becomes more and more difficult to distinguish between adjacent pulses because the resolution period is too short.

Mud pressure pulses can be generated in various different ways and the mud pulses may comprise modulation of pulse amplitude, pulse frequency and/or pulse phase. Whatever type of pulse system is employed, detection of the pulses at the surface is sometimes difficult due to attenuation and distortion of the signal and the presence of noise generated by the mud pumps, the downhole mud motor and elsewhere in the drilling system. Typically, a pressure transducer is mounted directly on the line or pipe that is used to supply the drilling fluid to the drillstring.

In MWD/LWD, the measured data may be communicated to the surface through mud pulse telemetry techniques, in which drilling fluid or “mud” is used as a propagation medium for a signal wave, such as a pressure wave. More specifically, data may be communicated by modulating one or more features of the wave to represent the data. For instance, the amplitude, the frequency, and/or the phase of the wave may be varied such that each variation represents either a single data bit (i.e., binary modulation) or multiple data bits (i.e., non-binary modulation) of digital data. As the wave propagates to the surface, these modulations may be detected and the data bits may be determined from the modulations. Mud pulse telemetry is discussed in more detail in U.S. Pat. No. 8,302,685, which is hereby incorporated by reference for all purposes.

As described above, during the drilling process mud is circulated through the drillstring. However, in order to drill a borehole, lengths of drill pipe must be added to the drillstring during the drilling procedure as the length of the borehole is increased. The adding of a section of drill pipe, which may be referred to as a stand, requires that a connection be made to connect the addition section of the drill pipe to the drillstring in the borehole. During the connection, the flow rate/pressure of the drilling mud in the drillstring drops. This typically results in the pressure of the mud dropping below the optimal operating pressure window.

When resuming drilling after a connection has been made, or after any other form of drilling break, the flow rate of the mud, and hence in turn the operating pressure, in the drillstring must be brought up to the level required for drilling.

As described above, the pressure of the drilling mud is critical to an effective drilling process and the pressure is repeatedly monitored and, in general, controlled to be in the optimal operating pressure window, where the pressure of the drilling mud is greater than the pore pressure of the formation to prevent fluid ingress into the borehole, and below a fracture pressure of the formation, to prevent fracturing the formation.

Because the drilling fluid pressure is so important for an effective drilling process, after a connection has been made, the drilling system is controlled so that the drilling fluid pressure in the top of the drillstring is increased back up to the desired drilling pressure. Most commonly, drilling pressure in the top of the drillstring is increased by pumping drilling fluid into the drillstring at the surface.

Commonly, because of the importance of maintaining the pressure in the drilling process within the pressure window, drilling fluid is pumped into the drillstring at a rate that increases the pressure in the drillstring to a level below the optimal operating pressure window, and then the pump rate is slowly increased to enter the optimal operating flow rate window, which slow increase in flow results in a slow increase in the pressure of the drilling fluid in the drillstring so that it slowly returns to a pressure within the optimal operating pressure window. Alternatively, the pumps may be brought straight up to the optimal operating flow rate required for drilling.

As will be appreciated, there will be a time delay between changes in flow rate at the top of the well and changes in pressure in the mud. Moreover these delays will become greater the deeper the well. In deep wells, even though the surface flow rate of drilling fluid is at the required level and the pressure at the top of the drillstring is at the desired level, it takes significant time for the flow rate of the drilling fluid throughout the pipe to stabilize, during which transition period mud pulse telemetry communication is unreliable.

Additionally, during the period when the new section of drill pipe is being added to the drillstring, it is standard practice for surveying instruments close to the bit to make measurements of the earth's magnetic and/or gravitational field, and these measurements are sent to the surface using pressure waves in the drilling fluid once flow is resumed. In order for these measurements to be received clearly at surface, it is advantageous if the flow rate in the drillstring is constant or near-constant. However, in long/deep wells and especially in wells drilled with oil-based drilling fluid (which drilling fluids are more compressible than water-based drilling fluid), there can be a considerable time before the flow rate along the drillstring, and through the drill bit, has stabilized after the flow rate from the pumps has reached its final level. This is due to the compressible nature of the drilling fluid, combined with the pressure created in the drilling fluid from the fluid flow along the pipe and through the bit.

Applicant has found that this transition period, particularly for deep wells, can be significantly and surprisingly reduced by increasing the flow rate of the drilling fluid at the top of the drillstring to a rate above an optimal operating flow rate for a limited time before dropping back to a lower, optimal flow rate. Moreover, Applicant has found that if the increase is only provided for a short period of time, the volume of additional fluid pumped into the drillstring is small, and as a result the pressure in the drillstring and the operation of the system does not have an opportunity to rise to an undesirable level outside the optimum pressure window.

As such, one embodiment of the present invention provides a method for controlling flow rates of drilling fluids being pumped into a drillstring during a drilling procedure to drill a borehole from a surface location through an earth formation, the method comprising: establishing a range of desired optimal flow rates for pumping the drilling fluids into the drillstring, wherein the optimal flow rates are determined so as to keep drilling mud pressure in the borehole within an optimal operating pressure window having upper and lower pressure bounds; drilling for a first period of time at a first optimal flow rate, maintaining the pressure within the optimal operating pressure window; reducing the flow rate to cause the pressure to fall below the lower bound of the pressure window; increasing the flow rate to a value above said first optimal flow rate; reducing the flow rate to a second optimal flow rate, which may be the same or different to the first optimal flow rate.

In such an embodiment, once the pressure drops below the minimum level for optimal operation, e.g. as happens when adding a section of drill pipe to the drillstring, the flow rate of drilling mud is increased so as to overshoot the final desired optimal flow rate for a period of time before falling back to the optimal flow rate. In this way the time required to achieve stable flow in the drillpipe may be reduced and the transition period, where mud pulse telemetry, is unreliable may be reduced. A benefit of this invention is that a stable flow rate at which reliable data communication can occur is achieved substantially faster providing for enhanced communication in the borehole.

In practicing the present invention it should be borne in mind that there can be a substantial time delay between a change in flow rate at the top of a wellbore causing an associated change in pressure of the mud, particularly mud near the bottom of the wellbore. Thus, in embodiments of the present invention increases in flow rates above that which it is desirable to operate at may be tolerable, provided they are for a limited period of time before the flow rate is reduced to an optimal level. Moreover, in embodiments of the present invention, an overshoot time and a flow rate may be used to process a volume of excess mud being pumped into the borehole and this volume may be processed to be a volume that will not increase the downhole pressure above the desired pressure window. Furthermore, as noted previously, the drilling fluid is compliant and the effect of changes in the flow rate of the drilling fluid being pumped into the borehole on the downhole pressure may be affected by this compliance, especially in deep boreholes.

In embodiments of the present invention, the pressure window for the downhole pressure determined from the reservoir pressure etc., the compliance properties of the drilling fluid and/or the like may be used to process a maximum flow rate increase above the flow rate of drilling fluid being pumped into the drillstring prior to a drilling stand and/or a period of time that such a flow rate increase can be performed. The amount of increase above the operating flow rate and the period of time this increase is applied during the drilling procedure will both increase the downhole pressure so in embodiments of the present invention, the two variables are processed to provide either a large increase in flow rate above the optimum flow rate for a short period of time or a lower increase for a longer period of time. By monitoring operation of the mud pulse telemetry after a drilling stand a determination may be made as to which of the alternatives is better for the ongoing drilling procedure. In embodiments of the present invention, a sensor or the like may be used to measure a flow rate of drilling fluid into the drillstring before a drilling stand and a processor may control pumps to increase the flow rate of the drilling fluid into the drillstring above the measured flow rate after the drilling stand is performed.

In embodiments of the present invention, the overshoot of the flow rate and the direction of the overshoot are determined such that the pressure in the drillstring does not exceed a desired pressure window and/or so that the perturbation in the flow rate/pressure of the drilling fluid is minimal and/or returns to the desired flow rate as quickly as possible.

In embodiments of the present invention, it has been found that even a small degree of overshoot in the flow rate for a relatively short period of time can significantly reduce the time taken for the pressure in the wellbore to stabilize, especially at the bottom of the wellbore.

Thus, the increased flow rate may be up to 30%, up to 20% and/or up to 10% greater than an optimal flow rate. Also the increased flow rate may persist for a period of time of the order of minutes and/or 10 s of seconds, e.g. less than 5 minutes. In some aspects it may be less than 2 minutes or even 1 minute.

Deciding on the how much faster to flow, and for how long, can be decided in a variety of different ways. There are a number of criteria that may to be accounted for as well as reducing the downhole time to stable flow, such as flow rate limitations imposed for the pumps, and the need to keep the surface pressure below a limit.

In accordance with an embodiment of the present invention, a first method for determining overshoot parameters is provided by modeling the flow/pressure of the drilling fluid in the drillstring, such as by using the theory of flow rate adjustments, as described in U.S. Pat. No. 8,196,678, which patent is incorporated by reference herein for all purposes.

In accordance with an embodiment of the present invention, a second method for controlling overshoot is to gradually increase the overshoot parameters from one connection to the next, while monitoring the pressure at surface (such as by monitoring stand-pipe pressure) to check that the maximum pressure stays within bounds that are acceptable, and preferably checking the observations with theoretical calculations to approximately infer the downhole flow rate from the observed pressures at surface. In some aspects, the overshoot may be outside of a range of flow rates that are determined as being necessary to maintain the downhole pressure within an operating pressure window—i.e., a pressure window bounded by the formation fracture pressure and the formation pore pressure—but because of the short duration of time of the overshoot may not introduce a sufficient volume of drilling fluid to take the bottomhole pressure out of the bounds of operating pressure window. Additionally, in some embodiments, choke pressure may be adjusted at the same time as the overshoot is performed to mitigate changes in bottomhole pressure produced by the overshoot.

In accordance with an embodiment of the present invention, the pump flow rate time series may either be controlled using an automated system, which follows the determined rate profile, or by an operator, who manually attempts to follow the time operations of the rate profile.

A processor in communication with a surface sensor may control the overshoot and the system may learn from previous overshoots to find optimum overshoot parameters for the drilling system and to improve the effectiveness of subsequent overshoots. Experience, knowledge of other drilling systems, modeling, experimentation and/or the like may be used to determine the overshoot parameters. Overshoot parameters and the surface pressure may be recorded, displayed, stored and/or the like to provide for an understanding/record/real-time analysis of the overshoot process and its effects. Additionally, characteristics of the operation of the mud pulse telemetry system may also be recorded, displayed, stored and/or the like to provide an understanding of the effect of the overshoot on the mud pulse telemetry operation.

In some embodiments, overshoot systems and methods may be integrated with a managed pressure drilling system, including an automated managed pressure drilling system. In some embodiments, properties of the drilling mud may be used to process the overshoot parameters.

FIG. 1B illustrates an apparatus for resuming interrupted communication down a wellbore, according to one embodiment of the present invention. As illustrated, a drillstring 101 is located in a borehole 102 that is penetrating through an earth formation 104. At the distal end of the drillstring 101 is a bottomhole assembly (“BHA”) 103 and a drill bit 105. The BHA 103 may comprise a turbine 109, a pressure pulse based communication system 110 and/or means of determining the orientation of the BHA with respect to the earth's magnetic and/or gravitational field 108.

At surface the drillstring 101 is suspended by sheaves 107, and there is a means for fluid to enter the drillstring 101 through a swivel 106. The swivel 106 is connected to a pump 112, which is controlled by an electrical control system 113. The control system 113 includes settings that may either come from an operator and/or a computer (not shown).

Although the apparatus illustrated in the figure uses jointed pipe, and sheaves, some embodiments of the invention may be used with systems such as coiled tubing drilling when flow is initiated through the tubing.

FIGS. 2-4 illustrate simulations of flows and pressures in a normal/previous wellbore operation, and simulations of flows and pressures in wellbore procedure operated in accordance with embodiments of the present invention.

FIG. 2 illustrates a flow rate transition according to current practice (solid line), and according to a method in accordance of the present invention (dashed line). In current practice the flow is brought up to a steady level (here 3000 litres/minute). According to one embodiment of the present invention the flow is first brought up to 3300 litres/minute, and then down to 3000 litres/minute after 30 seconds.

FIG. 3 shows flow rates through a drill bit versus time for a conventional wellbore procedure and a according to one embodiment of the present invention. With the normal practice, the flow rate downhole takes nearly two minutes to stabilize. With the flow rates following an embodiment of the present invention, this is achieved in about 40 seconds.

FIG. 4 shows stand-pipe pressures for a conventional wellbore procedure and a according to one embodiment of the present invention. Although a higher flow rate is used following the invention, the extra pressure seen at the surface is minimal, because of the short duration of the extra flow.

In accordance with an embodiment of the present invention, a processor controls the pumps. The processor controls the pumps to increase the flow rate of the drilling fluid so that is overshoots the flow rate that has been determined will produce the desired pressure in the drillstring/borehole for effective drilling, i.e, within the pressure window (as described in more detail above).

In aspects of the present invention, the processor may control the overshoot to minimize perturbations in the drilling fluid pressure. In some aspects, the processor may determine overshoot parameters that both provide for the quickest move from the transition period to the downhole flow rate necessary for effective mud pulse telemetry and only an acceptable increase in drilling fluid pressure in the borehole with respect to the pressure window. Because the pressure in the drillstring is of such importance, the processor may be in communication with a surface pressure sensor, such as located in the stand pipe, and may provide a display of the pressure changes produced by the overshoot. Tolerances may be built into the processor, to provide that the overshoot parameters provide for pressure perturbations that are a defined amount below a maximum pressure of the pressure window.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

1. A method for controlling drilling fluids in a drilling procedure to drill a borehole from a surface location through an earth formation to reduce interrupted communication through the borehole, comprising: receiving a range of desired optimal flow rates for pumping the drilling fluids into a drillstring, wherein the drillstring extends from the surface location down the borehole and the optimal flow rates are determined so as to keep a bottomhole pressure of the drilling fluid in the borehole within an optimal operating pressure window having upper and lower pressure bounds; pumping the drilling fluids into the drillstring at a first optimal flow rate configured to maintain the pressure within the optimal operating pressure window; reducing the flow rate of the drilling fluid below the first optimal flow rate; increasing the flow rate of the drilling fluid to a value above said first optimal flow rate; and reducing the flow rate of the drilling fluid from the increased flow rate to a second optimal flow rate, wherein the second flow rate is within the desired optimal flow rates and may be the same or different to the first optimal flow rate, and wherein reduction of the flow rate of the drilling fluid from the increased flow rate to the second optimal flow rate occurs over a period of time.
 2. The method of claim 1, wherein the reduction in flow rate to a rate below said first optimal flow rate is performed to provide for connecting a drill pipe stand to the drillstring.
 3. The method of claim 1, wherein the increased flow rate and/or the period of time are processed to provide that pressure in the borehole is kept within the optimal operating pressure window.
 4. The method of claim 1, wherein the increased flow rate is up to 30% greater than the first optimal flow rate, up to 20% greater than the first optimal flow rate and/or up to 10% greater than the first optimal flow rate.
 5. The method of claim 1 wherein the period of time is less than 5 minutes or less than 2 minutes or less than 1 minute.
 6. The method of claim 1, further comprising performing mud pulse telemetry after the second optimal flow rate is achieved.
 7. The method according to claim 1, wherein the steps of the method of claim 1 are repeated at a later point in time and data from the earlier steps are used to improve the effectiveness of the method carried out at the later point in time.
 8. A system for controlling flow rates of drilling fluids being pumped into a drillstring during a drilling procedure to drill a borehole from a surface location through an earth formation to resume communication through the drilling fluids after an interruption, the system comprising: a stored range of desired optimal flow rates for pumping the drilling fluids into the drillstring, wherein the optimal flow rates are determined so as to keep a bottomhole pressure in the borehole within an optimal operating pressure window having upper and lower pressure levels, wherein the upper pressure level comprises a pressure below a fracture pressure of the formation being drilled and the lower pressure level comprises a pressure above a pore pressure of the formation one or more pumps configured to pump drilling fluid into the drillstring; and a processor configured to control the one or more pumps, wherein the processor controls the pumps: to pump the drilling fluid at a first optimum flow rate, wherein the optimum flow rate is within the range of desired optimal flow rates; after a reduction in the rate at which the drilling fluid is pumped falls below the optimum flow rate, to pump the drilling fluid into the drillstring at an increased flow rate that is greater than the optimal flow rate; and to reduce the flow rate from the increased flow rate to a second optimal flow rate, wherein the second optimal flow rate is within the range of desired optimal flow rates and may be the same or different to the first optimal flow rate.
 9. The system of claim 8, further comprising: a pressure sensor in communication with the processor configured to measure a pressure in the drillstring.
 10. The system of claim 8, further comprising: a choke configured to control the pressure in the drillstring.
 11. The system of claim 8, further comprising: a mud pulse telemetry system.
 12. The system of claim 8, further comprising: a sensor for determining when a connection has been made in the drillstring.
 13. The system of claim 8, further comprising a display configured to display at least one of a flow rate of the drilling fluid into the drillstring, a pressure in the drillstring at the surface, a pressure in the drillstring at a lower end of the borehole and the pressure window.
 14. A method for controlling drilling fluids in a drilling procedure to drill a borehole from a surface location through an earth formation to reduce interrupted communication through the borehole, comprising: measuring a first flow rate of drilling fluid pumped into a drillstring during the drilling procedure before adding a section of drill pipe to the drillstring; and increasing flow rate of the drilling fluid pumped into the drillstring above the first flow rate immediately after the section of drill pipe has been added to the drillstring.
 15. The method of claim 14, further comprising: sending a mud pulse telemetry signal through the drilling fluid in the wellbore.
 16. The method of claim 14, further comprising: reducing the flow rate of the drilling fluid from the increased flow rate to a reduced flow rate.
 17. The method of claim 14, wherein the reduced flow rate comprises a flow rate configured to provide that a downhole pressure of the drilling fluid in the borehole is within an optimal operating pressure window
 18. The method of claim 17, wherein the flow rate of the drilling fluid exceeds the reduced flow rate for a period of time.
 19. The method of claim 18, wherein the increased flow rate and/or the period of time are determined to provide that the downhole pressure does not exceed the optimal operating pressure window.
 20. The method of claim 18, wherein the first flow rate is provided to be a flow rate within a desired range of flow rates, and wherein the desired range of flow rates comprise flow rates that maintain a bottomhole pressure within an operating pressure window having an upper pressure below a fracturing pressure of the earth formation and a lower pressure above a pore pressure of the earth formation.
 21. The method of claim 20, wherein the increase flow rate is outside of the desired range of flow rates.
 22. A system for controlling drilling fluids in a drilling procedure to drill a borehole from a surface location through an earth formation to reduce interrupted communication through the borehole, comprising: a sensor for measuring a flow rate of drilling fluid pumped into a drillstring during the drillstring procedure; and a processor in communication with the sensor and configured to control the pump to increase a flow rate of the drilling fluid pumped into the drillstring above a first flow rate immediately after a section of drill pipe has been added to the drillstring, wherein the first flow rate is a flow rate of the drilling fluid pumped into the drillstring before the section of drill pipe has been added to the drillstring.
 23. The system of claim 24, wherein the processor controls the pump to reduce the flow rate of the drilling fluid from the increased flow rate to a reduced flow rate.
 24. The method of claim 25, wherein the reduced flow rate comprises a flow rate configured to provide that a downhole pressure of the drilling fluid in the borehole is within an optimal operating pressure window
 25. The method of claim 26, wherein the flow rate of the drilling fluid exceeds the reduced flow rate for a period of time.
 26. The method of claim 27, wherein the increased flow rate and/or the period of time are processed by the processor to provide that the downhole pressure does not exceed the optimal operating pressure window. 